1. Field of the Invention
The invention relates to the generation of power. More specifically, the invention relates to the generation of power using a dimethyl ether fuel composition in a dry low NO.sub.x combustion system of a turbine.
2. Brief Description of Related Technology
The use of hydrocarbon fuels in a combustor of a fired turbine-combustor is well known. Generally, air and a fuel are fed to a combustion chamber where the fuel is burned in the presence of the air to produce hot flue gas. The hot flue gas is then fed to a turbine where it cools and expands to produce power. By-products of the fuel combustion typically include environmentally harmful toxins, such as nitrogen oxide and nitrogen dioxide (collectively called NO.sub.x), carbon monoxide, unburned hydrocarbons (e.g., methane and volatile organic compounds that contribute to the formation of atmospheric ozone), and other oxides, including oxides of sulfur (e.g., SO.sub.2 and SO.sub.3).
The specific fuel composition, the amount of air, the particular type of combustion system, and the processing conditions are among many variables that influence the overall efficiency of the process. In addition to maximizing the overall efficiency of the process, the ability to minimize the amount of environmentally harmful toxins produced as by-products of the fuel combustion is of great importance.
There are two sources of No.sub.x emissions in the combustion of a fuel. The fixation of atmospheric nitrogen in the flame of the combustor (known as thermal NO.sub.x) is the primary source of NO.sub.x. The conversion of nitrogen found in the fuel (known as fuel-bound nitrogen) is a secondary source of NO.sub.x emissions. The amount of NO.sub.x generated from fuel-bound nitrogen can be controlled through appropriate selection of the fuel composition, and post-combustion flue gas treatment. The amount of thermal NO.sub.x generated is an exponential function of the combustor flame temperature and the amount of time that the fuel mixture is at the flame temperature. Each air-fuel mixture has a characteristic flame temperature that is a function of the air-to-fuel ratio (expressed as the equivalence ratio, .phi.) of the air-fuel mixture burned in the combustor. Thus, the amount of thermal NO.sub.x generated is based on the residence time and the equivalence ratio of a particular air-fuel mixture. The equivalence ratio (.phi.) is defined by the following ratio: ##EQU1##
where m.sub.o is the mass of the oxidizer and m.sub.f is the mass of the fuel.
The rate of NO.sub.x production is highest at an equivalence ratio of 1.0, when the flame temperature is equal to the stoichiometric, adiabatic flame temperature. At stoichiometric conditions, the fuel and oxygen are fully consumed. Generally, the rate of NO.sub.x generation decreases as the equivalence ratio decreases (i.e., is less than 1.0 and the air-fuel mixture is fuel lean). At equivalence ratios less than 1.0, more air and therefore, more oxygen is available than required for stoichiometric combustion, which results in a lower flame temperature, which in turn reduces the amount of NO.sub.x generated. However, as the equivalence ratio decreases, the air-fuel mixture becomes very fuel-lean and the flame will not burn well, or may become unstable and blow out. When the equivalence ratio exceeds 1.0, there is an amount of fuel in excess of that which can be burned by the available oxygen (fuel-rich mixture). This also results in a flame temperature lower than the adiabatic flame temperature, and in turn leads to significant reduction in NO.sub.x formation.
In order to accommodate fuel-lean mixtures and to avoid the existence of unstable flames and the possibility of flame blow outs, combustors wherein only a portion of the flame-zone air is allowed to mix with the fuel at lower loads have been developed. These combustor systems are known in the art as "dry low NO.sub.x " (hereinafter "DLN") systems and are manufactured by General Electric Company and Westinghouse, for example. In addition to providing the user with the operability benefits described above, DLN systems also minimize the generation of NO.sub.x, carbon monoxide, and other pollutants.
A DLN combustor is generally known as a type of staged combustor in which a fraction of the flame zone air is mixed with the fuel at low loads or during start-up. There are two types of staged combustors: fuel-staged and air-staged. In its simplest configuration, a fuel-staged combustor has two flame zones, each of which receives a constant fraction of the combustor airflow. The fuel flow is divided between the two zones such that, at each combustor operational mode, the amount of fuel fed to a stage is matched with the amount of air available. In contrast, an air-staged combustor uses a mechanism for diverting a fraction of the combustor airflow from the flame zone to a dilution zone at low loads to increase turndown. These two types of staged combustors can be combined into a single system.
A DLN system typically operates in the following four distinct modes: primary, lean-lean, secondary, and pre-mix. In the "primary" mode of operation, a fuel is fed to primary nozzles in the primary stage of the system. A flame, referred to in this mode as a "diffusion flame," is only present in the primary stage. In this mode, the flame will tend to be located where the local air-fuel mixture is in a substantially 1:1 proportion so that the oxygen is completely consumed in the reaction (stoichiometric mixture, as noted above). This will be the case even if the overall air-to-fuel ratio in the flame zone may be fuel lean (.phi.&lt;1.0). This mode of operation is commonly used to ignite, accelerate, and operate the machine over low- to mid-loads (e.g., 0% to 20% loads using a natural gas fuel), up to a predetermined combustion reference temperature. NO.sub.x and carbon monoxide emissions generated in this mode are relatively quite high. The NO.sub.x emissions are driven by the peak temperatures in the flame, and a stoichiometric mixture will produce the hottest flame possible at given combustion conditions.
In the "lean-lean" mode, a fuel is fed to the primary and secondary nozzles. A flame is present in both the primary and secondary stages. This mode of operation is commonly used for intermediate loads (e.g., 20% to 50% loads using a natural gas fuel), between two predetermined combustion reference temperatures. Here, also, NO.sub.x emissions are rather high.
In the "secondary" mode, a fuel is fed only to the secondary nozzles and a flame exists only in the secondary stage. This mode of operation is typically a transitional mode between the "lean-lean" and "pre-mix" modes. The secondary mode is required to extinguish the flame in the primary stage before any fuel may be introduced into what becomes the primary pre-mixing zone.
The fourth operational mode is known as the "pre-mix" mode. Here a fuel is fed to both the primary and secondary nozzles, however the flame only exists in the secondary stage. Only about 20% of the fuel is fed to the secondary nozzles while the balance is fed to the primary nozzles along with air for "pre-mixing" prior to combustion. The first stage serves to thoroughly mix the fuel and air, and to deliver a uniform lean, unburned air-fuel mixture to the second stage. If properly designed and operated, there should be no regions of stoichiometric or near-stoichiometric air-fuel mixtures entering the flame zone and, therefore, the flame will be cooler than the adiabatic flame temperature, and produce substantially less NO.sub.x than a diffusion flame burning in the presence of an air-fuel mixture with the same equivalence ratio. The pre-mix mode is commonly thought of as the most efficient operational mode because it is in this mode that the NO.sub.x emissions are at a minimum and power generation is at a maximum (e.g., 50% to 100% loads using a natural gas fuel).
For power generation using gas turbines, DLN combustor systems are specifically designed to use natural gas (mostly methane, with varying amounts of non-methane compounds). For use with liquid petroleum-based distillate fuels, such combustor systems would require additional steam injection to reduce NO.sub.x and CO emissions. For power generation using gas turbines, other types of fuels, such as methanol or dimethyl ether manufactured from natural gas, coal, or biomass, which are amenable for ocean transportation or storage as a liquid fuel for peak power use, have also been proposed. For example, Bell, et al. U.S. Pat. No. 4,341,069 (issued Jul. 27, 1982) discloses the use of dimethyl ether mixed with small amounts of methanol (1.8 wt. % to 6.1 wt. %) and water (0.6 wt. % to 2.8 wt. %). Such fuels were formulated for use in combustion systems during an era when NO.sub.x emissions were not strictly regulated. The use of such fuels in conventional gas turbine combustors (designed specifically for natural gas fuels) operating under a diffusion flame mode could satisfy the lax NO.sub.x emissions standards of the past; however, use of these same fuels in a DLN system operating in a pre-mix mode may result in a high risk of flame flashback and a high risk of explosion. During flame flashback, the speed at which a flame propagates through the air-fuel mixture in the flame zone is higher than the speed of the air-fuel mixture at a given location in the primary mixing zone. As a result, DLN systems designed to burn conventional natural gas fuels will not operate in their most efficient mode, namely the pre-mix mode, with the dimethyl ether fuels, such as those disclosed in the Bell et al. patent.
It would therefore be desirable to provide a dimethyl ether-based fuel which can improve the efficiency of a DLN combustion system (e.g., operate in a pre-mix mode at loads below 50%). It would also be desirable to provide a fuel that can be used safely in a DLN combustor designed specifically to burn conventional natural gas fuels.